康涅狄格電力 (ES) 2005 Q4 法說會逐字稿

Thank you very much.

Good morning and thank you for joining us today.

My name is Jeff Kotkin and I am NU’s Vice President for Investor Relations.

Speaking [news] to you this morning will be Chuck Sivery, NU’s Chairman, President, and Chief Executive Officer;

David McHale, our Senior Vice President and Chief Financial Officer;

Cheryl Grise, NU’s Executive Vice President and head of our Distribution and Regulated Generation Operations; and [Lee] Olivier, NU Executive Vice President and head of our Transmission Operations.

Also joining us for q-and-a are Larry De Simone, President of NU Enterprises which houses our Competitive Energy subsidiary, and John Stack, our Corporate Controller.

Comments made during this earnings call may include statements concerning NU’s expectations, plans, objectives, future financial performance, and other statements that are not historical facts.

These statements are forward-looking statements within the meaning of the Private Litigation Reform Act of 1995.

In some cases the listener can identify these forward-looking statements by words such as “estimate”, “expect”, “anticipate”, “intend”, “plan”, “believe”, “forecast”, “should”, “could”, and similar expressions.

Forward-looking statements involve risks and uncertainties that may cause actual results or outcomes to differ materially from those included in the forward-looking statements.

Factors that may cause actual results to differ materially from those included in the forward-looking statements include, but are not limited to, actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, expiration or initiation of significant energy supply contracts, changes in levels of capital expenditures, developments in legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, effectiveness of our risk management policies and procedures, changes in accounting standards and financial reporting regulations, fluctuations in the value of electricity positions, the methods, timing, and results of the disposition of competitive businesses, actions of rating agencies, terrorist attacks on domestic energy facilities, and other presently unknown or unforeseen factors.

Other risk factors are detailed from time to time in our reports to the SEC.

We undertake no obligation to update the information contained in any forward-looking statements to reflect developments or circumstances occurring after the statement is made.

Now, let me turn over the call to Chuck.

Thank you, Jeff, and thanks to all of you for joining us today.

I would like to begin by updating you on the progress we’re making in executing both the strategic initiatives we announced in November and the more immediate tasks we set for ourselves for 2006.

As you remember, in November we announced that we would broaden our initial decision to divest our wholesale marketing and energy services businesses and would, in fact, divest all of our competitive businesses in 2006.

The proceeds of that divestiture will be invested in our regulated businesses, particularly electric transmission.

This strategic decision will effectively transform NU into a company focused on a regulated growth model.

It will also provide a simplified business model, a lower risk profile, and increased financial flexibility.

It should allow you to better predict our earnings and cash flow based on our investments in vitally needed utility infrastructure in our three-state service territory.

Each month we advance in transforming ourselves into a restructured company that will better meet our customers’ needs and create an attractive value proposition for our shareholders.

To that end, we have undertaken a complete review of our Company’s organization to assure ourselves that we are structured to meet our customers’ expectations and to provide a fair return to our shareholders.

Our regulated growth strategy is on track.

Two of our major projects that Cheryl and Lee will discuss with you later, the Bethel to Norwalk and our Northern Wood Power Project, are on schedule and on budget to be completed this year.

A third project, our Yankee Gas LNG storage facility in Waterbury, Connecticut, is on schedule and on budget to be completed next year in time to benefit our customers for the winter of 2007 to 2008.

Regulated Company operational performance was sound in 2005, despite the challenges posed by one of the hottest summers in the past several decades.

Regulated Company earnings were within the guidance we first issued in 2004, even including about $0.10 per share of severance costs we recorded in the fourth quarter.

We continue to believe that our regulated investments [that] build on schedule and earning the returns we expect of them will allow us to produce averaged earnings per share growth of 8% to 10% beginning in 2007.

While we focus on completing our transformation to our regulated business, we are aware of significant challenges this year.

One of those involved the impact that higher fuel costs are having on our customers.

The fuel and purchase power [in] gas components [of] rates have risen significantly at all our companies.

While these costs are passed through to our customers, we recognize that these increases are significant and can impact customer usage.

While changes in sales volumes do not affect the transmission business earnings, lower electric and natural gas sales do affect distribution company earnings.

Turning to the divestiture of our competitive businesses, we have reported previously that as of January 1 we exited all of our wholesale obligations in New England, once our biggest competitive market.

Our exposure to the New York and PJM marketplace continues to decline as our obligations roll off.

We have also made significant progress in divesting in our energy services businesses, closing on the sale of two of the six businesses and selling parts of another, receiving a total of $8.5 million in cash.

We continue to make progress on divesting in our other three services businesses, which include two electrical contracting firms, an energy service business, and the remaining elements of an [HBAC] business.

In December, we announced that we had retained J.P.

Morgan as our financial advisor in the sale of our competitive generation and competitive retail energy marketing businesses.

Sales documents were distributed to perspective buyers of the retail business in January and indicative bids were just recently received.

We expect to distribute sales documents to perspective buyers of the generation next week.

We continue to be encouraged by the progress being made and by the interest exhibited by perspective buyers.

We also continue to expect that we will close on the retail marketing business around the middle of this year and close on the generation business before year-end.

Overall, I am pleased that our regulated businesses had a strong year in 2005, with net income of $163.4 million compared with $155.6 million in 2004.

Our electric transmission business earned $42.5 million in 2005, more than a 40% increase over earnings of $29.5 million in 2004.

I believe that our results demonstrate that we are on track with our regulated growth strategy as we continue to invest in improving New England’s energy infrastructure.

Now, let me turn the discussion to David.

Thank you, Chuck.

As you read in the news release, NU lost $253.5 million in 2005, with losses of $398.2 million at NU Enterprises and $18.7 million as a parent company, and earnings of $163.4 million as a regulated company.

Chuck mentioned that our regulated businesses had strong financial results for the full-year 2005, with net income of $163.4 million versus $155.6 in 2004.

The fourth quarter was equally strong with earnings of $49.1 million in ’05 compared with $37.2 million in 2004.

The regulated distribution results include after-tax severance charges of $12.3 million in connection with the restructuring undertaken by the Company, including $8.5 million at the Connecticut Light and Power Company.

In terms of our transmission businesses, the improvement in year-over-year fourth quarter operating results was driven in large part by our higher levels of capital expenditures in plant in service, which drove rate-based growth.

As would be expected, most of the growth of transmission earnings occurred at CL&P, where we earned $30.7 million in 2005 compared with $19.8 million in 2004.

That increase was due primarily to higher transmission investment levels, but certainly around our Southwest Connecticut project, including the Bethel to Norwalk project, which will be completed later this year.

Transmission earnings in 2005 were up about $1 million at both PSNH and Western Mass Electric compared to 2004.

In terms of our distribution businesses, I’ll first address CL&P.

Improvement in CL&P’s fourth quarter results was due to a rate increase effective on January 1, 2005, the absence of $3 million in charges in 2004 to reflect a full year of earnings [sharing], an additional $3.7 million of earnings to reflect a 2004 incentive procurement [state], very cold December weather, which drove a nearly 4% increase in fourth quarter electric sales, and some additional federal tax benefits we recorded in connection with retiree healthcare costs.

For the full year, CL&P’s distribution earnings were $58.6 million in ’05 compared with $62.7 million in 2004.

The decline in full-year results was due to several factors, including the absence of a $6 million benefit we received in ’04 when a pension charge related to a 2003 rate decision was reversed and, of course, the $8.5 million severance charge discussed earlier.

Due to hot summer weather, CL&P’s retail sales were up 3% in 2005 compared with ’04.

CL&P’s earned regulatory ROE was 7.5% in 2005, including the effect of the severance charge, compared with 10.58% in 2004.

This reflects both lower earnings and a higher equity base.

CL&P’s allowed cost to capital ROE is 9.85%.

So unlike 2004, there was no sharing of over earnings in ’05.

PSNH’s distribution earnings fell to $33.9 million in 2005 from $39.9 in ’04.

The primary reason for the reduction was higher operating and interest expenses, partially offset by PSNH’s rate increases of $3.5 million in late ’04 and $10 million on June 1, 2005.

PSNH’s sales were up 1.9% in 2005 compared with 2004, mostly due, again, to hot summer weather.

Year-over-year industrials fell by about 6% due to a number of customers [floating] their businesses and a large customer beginning to self-generate.

PSNH’s earned distribution ROE was just over 9% in 2005, including the severance charge.

To remind you, PSNH’s fully-tracking allowed generation ROE is 9.62%.

Western Mass Electric’s distribution business earned $11.1 million compared with $9.4 million in 2004.

WMECO benefited from a $6 million distribution rate increase that took effect January 1, 2005.

WMECO’s retail sales were up 1.4% in 2005 compared to ‘04, due again to hot summer weather.

Western Mass’ distribution ROE for the full year was about 7.7%.

Yankee Gas earned $17.3 million in ’05 compared with $14.1 million in 2004.

Yankee benefited from a $14 million distribution rate increase and a reduction in depreciation, most of which resulted from a late 2004 rate [allowance].

Yankee’s firm sales rose 1.5% in 2005 compared with ’04.

Yankee’s regulatory ROE was about 8.4% in 2005 compared with an allowed return of 9.9%.

We continue to believe that our earnings [move] to our more competitive businesses will be between $1.09 per share and $1.22 per share in 2006, the same range disclosed at the EEI conference in November.

We now believe that due to higher projected investment income and a number of additional factors NU parent losses will be less than the $0.09 to $0.12 a share we estimated earlier.

We also believe that a combination of mild winter, slowing non-weather related sales, and the denial of interim rate relief for Yankee Gas this year may cause our distribution in regulated generation earnings to come in somewhat lower than our previously estimated range of $0.89 to $0.96 a share.

At this time, however, we are not adjusting our earnings ranges, [but] will update you on our projections for the quarter.

We continue to estimate transmission business earnings of $0.32 to $0.35 a share and do not anticipate any change in this segment of our business.

Turning to our competitive businesses, you can see that we lost $398.2 million in 2005, including $54.1 million in the fourth quarter, much of it expected as disclosed in our third quarter 10-Q.

The primary reason for the 2005 losses was a requirement that we mark-to-market our wholesale contracts, many of which are below market.

The negative mark on future wholesale obligations was $278.9 million after-tax in 2005.

That includes the $242 million pre-tax that we either did pay or agreed to pay to terminate our New England wholesale obligation.

Aside from the mark-to-market charges, we also recorded $27.3 million of restructuring and impairment charges in 2005.

Those were mostly recorded in the first quarter.

We also performed an impairment analysis at the end of 2005 on our 1,440-megawatt to competitive generation, which has a book value of about $825 million, and concluded that an impairment of that investment was not warranted.

On an operating basis, the wholesale business lost $41.9 million in ’05 and $1.5 million in the fourth quarter.

As we mentioned, again, at the EEI conference, our wholesale business was negatively affected by higher summer loads, which required us to acquire additional power and capacity at prices above the revenue stream we are receiving from our customers.

In the fourth quarter, we recorded a $39.6 million charge related to wholesale contract market changes and another $9.2 million due to restructuring and impairment charges related to merchant energy.

The wholesale charges were related to two factors we noted in November and on our equity road show.

The first is related to the continuing mark-to-market of additional costs we expect to incur on a wholesale contract in the PJM power pool where commercial industrial customers are leaving their competitive electricity supplier and returning to the utility provider, [a] last resort service.

As those customers return, we need to acquire additional energy in the marketplace at a cost that exceeds our incremental revenue.

Another factor involves payments we agreed to make in the fourth quarter to fully divest our New England wholesale portfolio that were in excess of our September 30th margins.

Excluding the effects from the previously defined transfer price, the competitive retail business earned $2.4 million in the fourth quarter of 2005 and $6.3 million in all of 2005, slightly exceeding our expectations in the $4.9 million we earned in 2004.

As Chuck mentioned earlier, our goal is to sell the retail business, as a going concern, and I am pleased to report that we continue to sign up new customers and renew existing loads.

In 2005, we were the successful bidder on more than 30% of our bids from a revenue standpoint, up from just under 25% in 2004.

Our delivered electricity increased 6% from ’04 to 2005, from 10.6 million megawatt hours.

Delivery of natural gas increased to 20% from 2004 to 47.4 billion cubic feet in 2005.

Our margins on retail sales in 2005 were between $1.60 and $2.00 per megawatt hour and natural gas margins were in the $0.20 to $0.25 range per thousand cubic feet.

As disclosed in the third quarter 10-Q, the decision to sell the retail business required us to evaluate our retail sales contract to determine whether they are derivatives and, if so, should be marked to market.

After a thorough review, we concluded that we should not mark our retail contracts to market at the end of 2005 because these contracts are not derivatives.

The accounting rules also did not allow us at this time to record a loss for the negative value of those contracts.

We will revisit whether or not recording a loss is appropriate at the end of the first quarter.

This conclusion also will depend on the status of the retail sales [progress].

However, not recognizing these losses in 2005 will announce higher operating losses in 2006.

As Chuck noted the status of the generation sale process earlier, I will update you on the 2005 operating performance, which was strong for the year.

Our Mt. Tom coal-fired generating stations generated more than 1 million megawatt hours and achieved a capacity factor of just over 80%.

Our conventional hydroelectric unit generated more 700,000 megawatt hours and had an average availability factor of more than 85%.

Our 4-unit 1,080-megawatt Northfield Mountain pump storage unit had an average availability factor of nearly 95%.

Our services business and NUEI parent lost $37.6 million in 2005 compared with earnings of $2.2 million in ’04.

Of that 2005 loss, $33.6 million was the result of impairment charges and to discontinued operations.

Now, turning to our financing and capital investment plans, our regulated capital expenditures were $755.3 million in 2005 compared with $598.4 million in 2004.

The increase was primarily the result of higher transmission investment.

In 2006, we project regulated capital expenditures will approach $900 million, with the increase again on the transmission side of our business.

As you will recall, we issued 23 million shares of additional common equity in December at $19.09.

We upsized the offering from an initial 16.5 million shares to the [$] 23 million figure due to very strong investor demand and the very fair share price.

The $425 million in net proceeds has essentially reduced our short-term debt to zero and has allowed us to have a significant amount of cash at the parent company to invest in our regulated utilities.

The equity issuance also allowed us to significantly improve our capitalization ratio at year-end.

At December 31, 2005, our consolidated capitalization was approximately 55.7% debt, 42.2% common equity, and 2.1% preferred.

This debt level is several hundred basis points lower than what we had projected for year-ended 2005 at EEI.

There are a number of reasons, including, of course, the upsized equity offering.

In addition, we did not incur all of what we committed to pay in the fourth quarter to buy out of Select wholesale obligation.

However, additional payments are expected this year as we work to fully divest our wholesale line of business.

Nevertheless, our capitalization targets remain unchanged.

We continue to target utility equity capitalization levels at about 45% equity and continue to [inject] equity into our utilities, particularly in the [GEN&P] to achieve that level.

Also, we continue to expect that our consolidated capitalization will be approximately 40% equity, 60% debt as we move towards a fully-regulated company.

We have discussed our targets at length with the rating agencies over the past month and firmly believe that those levels are consistent with their views of an investment-grade regulated company.

We said at the road show that we do not expect to return to the market to sell additional equity until at least 2008.

That exact timing will depend on a number of factors, including the [take] in non-construction proceeds and proceeds from the sale of our competitive generating assets and any enhancements to cash flow that may develop from the first transmission [notebook].

Now at this point, let me turn the call over to Cheryl Grise.

Thank you, David, and good morning everyone.

Our distribution and regulated generation businesses performed well in 2005.

Financial performance in 2005 benefited from about $55 million of rate increases that we received across the four utilities and from one of the hottest summers we have had in decades.

As a result of the weather, residential electric sales were up by 4.4% and commercial electric sales were up by 3.6% in 2005 as compared to 2004.

This more than offsets a 4% decline in industrial electric sales.

When we adjust for weather, however, we estimate that our electric sales were essentially flat from 2004 to 2005, and with significant commodity-driven rate increases taking effect earlier this year and the weather being much milder to-date this year than it was in 2005, we are concerned that actual sales could be lower in 2006 than in 2005.

We implemented two previously approved rate increases on January 1, 2006.

CL&P put into effect an $11.9 million increase and Western Mass Electric raised rates by $3 million.

While these increases will help our performance, we believe they may be inadequate to offset a possible combination of lower retail sales, higher employee related expenses, and higher costs related to our distribution capital investment program.

We are now in the process of looking hard at all four of our regulated businesses to determine where we can simplify our business processes and create further cost efficiencies.

We also plan to file this year for rate relief at each of our three electric companies.

A request to implement an interim Yankee Gas rate increase was denied by the Connecticut Department of Public Utility Control as not allowable under our 2004 rate settlement.

As a result, we will need to wait until late this year to file a full Yankee Gas rate case, which for the rate settlement will take effect the earlier of July 1, 2007 or when our 1.2 Bcf LNG facility goes into service.

Turning to some of our major projects, the Waterbury Connecticut LNG project I just mentioned is about 44% complete and is on schedule.

Our $75 million Northern Wood Power Project at Schiller Station in Portsmouth, New Hampshire is nearly 90% complete and is expected to commence commercial operations this summer.

Also in New Hampshire, we have a number of other regulatory and legislative items coming up this year.

New Hampshire lawmakers will consider new mercury reduction rules.

In November, we reached an agreement with legislative and environmental leaders in the state to install wet scrubber technology at our two Merrimack coal units, which together can generate 433 megawatts of electricity.

We are hopeful the agreement will be codified into law this spring, resulting in a workable plan to reduce mercury emissions by 80% at a minimum by mid 2013.

In addition, when installed, this technology will reduce sulfur emissions by more than 90%.

This project would cost about $250 million and, like the Schiller project, would become part of our regulated generation rate base.

On Monday we announced the receipt of a $2.5 million United States Department of Energy grant to study mercury reduction efforts at Merrimack Station over the next 18 to 24 months using carbon injection technology.

As David mentioned, we are allowed to earn a 9.62% on our New Hampshire generation rate base, so we have appealed a recent decision specifying that return to the New Hampshire Supreme Court.

Operationally, PSNH’s generation had another good year in 2005.

Unit availability was 86.4%, and perhaps most importantly, availability was nearly 95% on the very highest priced days in New England.

That indicates that our units were available when they were needed.

The capacity factor of our base load units was 80.7% and our total generation was about 5.6 billion kilowatt hours, allowing us to generate about 70% of our retail customers’ needs.

This fact saved customers between $75 million and $100 million.

This compared to the cost of buying 2,000 [needs] in late 2004.

We expect savings to be even greater in 2006.

Of the 5.6 billion kilowatt hours generated, 3.1 billion kilowatt hours were generated at the Merrimack Station where we are looking to install the scrubbers I just discussed.

We expect PSNH to file a T&D rate case later this year, but an increase in T&D rates would be more than offset by a decline of approximately $170 million a year of stranded cost recoveries.

As a result, we may propose a net rate reduction later this year, assuming the recent sharp increases in fuel and power costs abate somewhat.

Western Mass Electric expects to file a rate case in the middle of this year to be effective January 1, 2007.

CL&P has another distribution rate increase of $7 million already approved to take effect on January 1, 2007, but at this time we believe that increase will be insufficient to cover our rising distribution costs.

We now expect to file for rate relief in Connecticut later this year.

We anticipate the next three months will be an active period at the Connecticut legislature.

The three-year transitional standard offer period will expire at the end of this year, and we expect legislators to consider whether they want to make further changes in the electric utility restructuring that began here in Connecticut in 2000.

CL&P will participate actively in that conversation.

A topic of considerable interest to our regulated companies involves the structure of the New England capacity market.

On January 31st, a settlement judge informed the FERC that a significant majority of the parties that had been active in the discussion about Locational Installed Capacity, so-called LICAP, had agreed in principle on an alternative plan to induce the construction of needed capacity in New England.

A term sheet is now being reviewed and the judge said he hoped it would be filed with FERC by March 5th.

Due to confidentiality provisions, we cannot discuss the alternate plan in detail, but I can tell you that we are supportive of it.

At this time, I’d like to turn the call over to Lee Olivier.

Thank you, Cheryl.

As David mentioned, transmission really had a very good year in 2005.

Earnings were above our guidance of $0.32 per share compared with $0.23 per share in 2004.

Our capital spending for the year totaled $257.3 million as compared with $170 million in 2004, and included significant progress on our Bethel to Norwalk project, which is nearly 70% complete.

As part of the project, we energized a new 6.2-mile segment of overhead 115-kV line rebuild that is required to start the final 345-kV construction of this project.

We also placed $175 million of plant in service in 2005, significantly exceeding our own original expectation of $66 million.

Though it is obvious that 2005 was a strong year by all quantitative measures, the most important outcome may be that we are now well-positioned for 2006 and beyond.

We have all necessary siting and ISO New England approvals for each of our four major Southwest Connecticut projects and are poised to invest in excess of $450 million in our transmission infrastructure in 2006, with investments up to $2.3 billion over the next five years.

About 80% of our 2006 investment will be in five Connecticut projects-- four in Southwest Connecticut and a new substation in Northeast Connecticut.

On our $1 billion Middletown to Norwalk project, a project being jointly constructed with United Illuminating, we have all necessary siting and technical approvals and are poised to begin physical construction in the second quarter, and we will invest over $140 million this year.

We continue to work with ISO New England and National Grid on preliminary planning studies and analysis of a project referred to as the Southern New England Transmission Reinforcement Project.

By early 2007, we hope to have identified the preferred route.

We have begun the ISO technical approval process for this project.

This project will likely involve a major 345-kV backbone reinforcement throughout the southern New England area and could require significant capital investment starting as early as 2009.

On the regulatory front, we are awaiting the final FERC decision in the [RTO] proceeding that will establish the allowed return on equity for NU as well as other New England transmission owners.

Also, on the FERC front, in November of 2005 we filed with FERC a request to include 50% of the construction work in progress, or CWIP, in rate base for our four major Southwest Connecticut projects, thereby providing the Company with current cash and earnings return on those expenditures rather than continued non-cash accruals of AFUDC.

I am pleased to report that FERC approved our CWIP request and will begin reflecting CWIP in our rates effective February 1, 2006.

In conclusion, 2005 was a very good year with strong operating performance and earnings, with significant progress on many of our important projects.

Again, perhaps most importantly, we are now positioned to build upon these successes as we move into a challenging and exciting 2006.

Now what I would like to do is return the call to Jeff Kotkin.

Thank you, Lee, and I will return the call to Marylee, our conference operator, so she can remind you how to enter questions.

[OPERATOR INSTRUCTIONS].

Thank you.

Our first question is from [Ushar Kahn].

Ushar?

Hi.

Good morning.

Can you just tell us--?

You had provided us with some rate-based numbers for the businesses in the last year.

Are those rate-based numbers now pretty much the same with your CapEx plans?

I was just trying to just get a confirmation of the rate-based growth numbers that were provided in the last EEI.

This is David McHale.

That CapEx figure of about $900 million is very close to what we shared with you at EEI on the road show.

So the rate-based projections that we had discussed earlier are quite consistent with our views today.

Okay, and David could you just mention, because as you mentioned some of the cash proceeds got--?

I guess cash outflows got pushed to this year.

Could you just go over what expected cash outflows and inflows are expected into the system through getting the discontinued operations, all of them, out of your books?

Sure.

We had talked earlier about our previous commitment of about $245 million to exit the New England business.

We paid-- the New England wholesale book of business, we paid all but about $50 of that in 2005, so there remains $50 in 2006 that was previously committed to and we’re working through that particular discussion now.

In addition to that, we have retained, at least at this point, our PJM contract and our one single New York contract in [NIMFA].

We are continuing to work towards divesting those.

So those cash flows, those positions, as you know, are negative mark-to-market.

They are-- those losses are recognized in our financials as of ’05, but the cash flows are on the horizon should we successfully negotiate those transactions and, again, we are moving ahead to do just that.

Second, as we divest our retail book of business in that franchise, we know and we’ve shared with you in our third quarter disclosure that that business also at least as book had a negative mark-to-market, and depending on the sales process and the amount that we receive for that business, there could be a cash outflow there as well towards the middle of the year.

And then lastly in terms of thinking through the other material cash flows, as Chuck and I stated, our generation business now is in the market.

We are in that process and we do expect to reach a sale of that later this year and we are expecting very significant cash inflows as a result of that transaction. [Net-- net] we do expect to receive positive cash flows from the full divestiture of all of our competitive businesses by the time we work through all of 2006.

Could you just mention what that range could be David, just to give us an idea?

Yes.

I think the question was raised and addressed a number of times, again, in our December equity road show, and I think that we characterized that net and this is sort of an after-tax number of in the $200 million range.

Where do you expect the debt-to-equity ratio to end up in ’06?

I think at this point our leverage is a little bit more conservative for the reasons that I outlined, but I still think that we’re going to end up at an NU consolidated level at about 60% total debt to total cap.

At the end of ’06?

Correct.

Okay.

Thank you.

Thank you Ushar.

Our next question is from [Anthony Crowdell] from Jefferies.

Anthony?

Hi.

Good morning.

I guess my question’s sort of on the lines of Ushar with the valuations for the generating assets, particularly Northfield.

What type of value do you see per kW in the sale?

And also with LICAP or a version of LICAP coming to fruition, do you see the valuation changing?

This is Chuck Shivery.

As we spent a lot of time chatting about the valuation of both retail and the generation assets when we were on the road show, as you can appreciate, we’re right in the middle of an auction process and right in the middle of a bid process.

We really don’t think it’s appropriate for the Company to be talking specifically about the valuation of those assets.

There have been a couple of research reports written by folks that can give you a range, but at this point in time, we are not specifically putting a value on those assets other than, of course as David said earlier today, that we’ve reached the conclusion that there was no impairment in those generation assets.

With respect to LICAP, Cheryl touched on it briefly, but there are-- really there are two kinds of sets of data points out there.

The first is the data point that ISO submitted a number of months ago that has a demand curve and a particular set of LICAP values, and we’ve spoken with you about that in the past.

The other, of course, is the potential settlement that Cheryl referenced in her remarks.

But, as she also said, that is under a strict confidentiality agreement and we really can’t talk about that.

If the schedule is met, however, that information should be public on March 6th and you’ll get a chance to see it then.

Thank you.

Thank you Anthony.

The next question is from [Erica Nasurshia] from Merrill Lynch.

Erica?

Hi you guys.

How are you?

A quick clarification question and maybe I missed this.

When you talked at the beginning of the call about reaffirming 2006 guidance of $1.09 to $1.22 for the regulated subsidiaries and the parent, did you mention what the individual--?

I think you said obviously you’re expecting the regulated to come in potentially lower than the $0.80, $0.90, $0.96, but that the parent costs would be less.

What’s the--?

What are the individual ranges for those two separate area segments?

Erica, again, this is David.

We have not shared or put forth new ranges at this time.

We do know as we look at the parent company expenses that they will be less than guidance, and one of those reasons, obviously, is because we upsized the equity offering and took in more cash proceeds, and because we paid out less in terms of our overall contract buyouts, we’ve gotten some additional interest income there, but we haven’t been any more quantified than that.

And on the distribution/generation businesses, what we’ve said is we’ll continue to watch this in terms of where we are with sales, where we are with our cost containment initiatives here, and where we are on our regulatory strategy, but we have not put forth a new specific number.

Okay.

I mean I guess the numbers-- I guess the range then, the $1.09 to $1.22 as you had originally built it would be $0.89 to $0.96.

That-- it’s my understanding that the low end of that range encompassed some rate relief, but that was a low level.

Is that correct?

Are you now assuming no rate relief in reaffirming your guidance today?

You’re right on the assumption of the rate relief.

It was a modest amount of rate relief.

I think what we do know is that there will be it’s most likely no rate relief for Yankee Gas this year given that the Commission denied our interim rate relief request.

We shared with you in December that very shortly after the New Year we would initiate a Connecticut rate case.

We will do that later this year, but of course the further we push out that Letter of Intent and the supplement filing, the fewer revenues flow in 2006.

Okay, so the guidance which you’ve reiterated today does allow for the possibility of no rate relief in 2006, is that correct?

The guidance that we’ve given here-- and this is we’ll stick with the $0.89-- that will require some rate relief in 2006 to achieve that low end of the guidance.

Okay.

And one last question on the-- I guess on the generation sales we’ll be hearing about the settlement, the specific settlement details, from LICAP at the beginning of March.

Is it correct?

Should we assume that you’re going to-- as far as when you put out the offer letters for the generation that you’re going to wait to see how that turns out, and so, when those offer letters-- when the letters go out that you’ll have that reflected in the valuations that you get back from potentially interested bidders?

We would expect that prior to receiving final bids for the generation that the information on LICAP in the settlement is public information.

Thank you.

Thank you Erica.

The next question is from Steve Fleishman at Merrill Lynch.

Steve?

Hi.

Sorry to monopolize the call a little here with questions, but just one more time to clarify maybe with Dave.

You reiterate in your guidance the parts might be different, but it’s the same guidance.

Is that fair?

That’s fair.

So even though you’re not giving new guidance on the parts, you’re still okay?

One might be better, one worse, but the range is still okay?

That’s exactly right Steve.

Okay.

And I guess a question on the generation.

Have you found by any chance any avenues that might protect some of the tax leakage on that?

Steve, we’ve looked at that briefly and I would say at this point we have really-- we haven’t found any kind of avenues or financial engineering to prevent that particular tax payment, which, as you know, is a meaningful payment of [cash] taxes later this year.

It’s something that we may continue to study, but at this point our planning is such and our liquidity is such that we are expecting to make that tax payment.

Okay.

And then just, finally, I guess on the transmission business and plan, FERC has also been talking in their NOPR about structures that would allow maybe obviously the CWIP and rate base that you’re talking about, but also maybe even kind of a more leveraged capital structure and the like.

What are you assuming on how you finance your new transmission investment and is it possible you could kind of even if it’s not independent that you would be able to finance it with less actual equity investment?

Steve, in terms of what we’re planning for now driving both our guidance and the rate-based growth that you’ve seen and the long-term earnings growth that we’ve discussed, it was really a very sort of traditional, if you will, view of the capitalization, 55/45, which mirrors the Connecticut Light and Power’s overall capital structure, and an 11.5% ROE, as you know.

I do think and we are quite optimistic that the NOPR does hold some promise for us going forward, both in generating higher levels of earnings and cash flow, but at this point we haven’t built them into our ranges or our guidance.

But I think if you look at an ability to get a 1% higher ROE, if you think that that’s on the horizon, that could produce another $10 million of cash for us, another $5 to $6 million of earnings for us.

And if you look at the benefits that could be afforded by going from 50% CWIP to even 100% CWIP, that could be depending on where we are in our bill cycle, between $15 and $20, maybe even upwards of $20 million of additional cash flow.

And I think also, depending on how you read the FERC policy language, one could argue that to receive these benefits you do not need to be a fully independent entity.

That remains to be seen, but we do think that there are some benefits on the horizon for us.

Okay.

Thank you.

Thank you Steve.

Our next question is from [Paul Caviston] from [Glen Ross Associates].

Paul?

Good morning guys.

How are you?

Listen, I apologize for--

You there?

Paul?

I think we lost that connection.

Why don’t we move to our next question, which is from Ushar Kahn from [SAC].

Ushar?

David, can you break up the transmission, like the CL&P earnings between transmission and non-transmission 2005?

Yes.

In fact, it is contained in one of the tables deep in the press release.

I apologize.

I’d be happy to kind of discuss that with you.

For all of the distribution businesses this year we earned $38.2 and for the-- in the fourth quarter, and for transmission in the fourth quarter $10.9.

For the full year for the distribution and reg generation $120.9 and for transmission $42.5.

Okay, and is the majority of the increase ’06 versus ’05 is that at CL&P?

Yes it is.

Okay, so we should just assume that those transmission earnings are just going to add into CL&P.

And can you just talk about--?

One of the premises for filing the case this year in CL&P was that on a weather-adjusted basis sales weren’t growing.

Could you just mention what your experience has been on a weather-adjusted basis for the first month?

Is that something which is carrying over in 2006?

Does the evidence point to that if you look at January sales?

Ushar, this is Cheryl.

I will answer that question.

For NU on electric sales on a weather-normalized basis, our sales January this year to January of ’05 are down 1.4%.

On a weather-normalized basis?

Yes.

So that trend is still continuing?

Yes.

We are seeing that.

That’s for the first month of January.

And we see, as we have seen in the past, a harder hit in our industrial sales.

And could you just mention the timing of this case?

We haven’t determined that yet, but I would expect that it would be probably late in the second quarter.

Okay, so that would imply Cheryl any kind of decision is really at the end of the year right?

That’s what we would expect yes.

We are expecting some relief this year, but it will be late.

It would be late.

Okay.

And any talks why this is happening?

I know you-- anything more to share as to any more evidence points or anything why and why it’s happening?

No.

We just think that our customers are reacting to the increases that they’re seeing in their bills that are driven by the commodity costs.

So it’s just-- it is pure conservation on our customers’ parts in reaction to high costs.

And the new rates went into effect January 1?

Yes.

Okay.

Thank you.

I think that’s the last question.

So I want to thank you all for joining us today.

If you have any more follow-up questions, feel free to give us a call and have a good day.

Thank you very much.